埃克西爾能源 (XEL) 2012 Q2 法說會逐字稿

Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Xcel Energy second-quarter 2012 earnings conference call. (Operator Instructions). This conference is being recorded today, August 2, 2012.

I would now like to turn the conference over to Mr. Paul Johnson. Please go ahead, sir.

Thank you, and welcome to Xcel Energy's second-quarter 2012 earnings release conference call. With me today are Ben Fowke, Chairman, President and Chief Executive Officer; Teresa Madden, Senior Vice President and Chief Financial Officer; Dave Sparby, Senior Vice President and Revenue Group President; Scott Wilensky, Senior Vice President and General Counsel; George Tyson, Vice President and Treasurer; and Jeff Savage, Vice President and Controller.

Today we will provide you with an update on recent business development, discuss second-quarter results, and update you on our 2012 guidance. Please note that there are slides that accompany today's call which are available on our webpage. In addition, we will also post a short video at our website with Teresa Madden summarizing our results. We encourage you to check it out.

As a reminder, some of our comments may contain forward-looking information. Significant factors that could cause results to differ from those anticipated are described in our earnings release and our filings with the SEC. I will now turn the call over to Ben.

Thanks, Paul, and good morning. Today we reported second-quarter earnings of $0.38 per share compared with $0.33 per share in 2011. New electric rates in Colorado, combined with warmer than normal June weather across our service territory and continued strong expense control led to our solid second-quarter results. As a result we remain on track to deliver 2012 earnings in the lower half of our earnings guidance range of $1.75 to $1.85 per share. Teresa will discuss our quarterly results and earnings guidance in greater detail in a few moments.

I will now provide you a few recent developments, starting with an operational update. I am pleased to report that our operating systems performed very well throughout the recent period of hot weather across our service territories. Record temperatures drove new peak demands in several states with only minimal service interruptions.

In addition to the record heat, numerous severe storms occurred in our Northern service territory. Excellent response planning and performance during system outage events minimized customer impacts, and our crews performed their work safely under difficult conditions.

In addition to reliability, our efforts to provide value to our customers are also reflected in two recently proposed transactions. This summer we agreed to purchase the Brush assets for $75 million. The Brush assets consist of 3 gas-fired generating units with a total capacity of 237 megawatts.

These plants currently provide energy and capacity to PSCo on our purchase power agreements that are set to expire in 2017 and 2022. While smaller, this transaction is very similar to our acquisition of generation assets from Calpine in late 2010, which provided benefits to both customers and investors.

The Brush acquisition has many positive attributes, including saving our customers money beginning in the first year. Additionally, owning these peaking plants will give us greater control over our resources. The purchase is subject to various regulatory approvals, including the Colorado Commission. We anticipate this transaction will close in early 2013.

We have also asked the Commission to consider our request to retire at the end of 2013 Arapaho Unit 4, a 109-megawatt coal-fired power plant. Previously we planned to switch this unit to natural gas. We have proposed replacing the retired unit with a PPA.

One final item before I turn the call over to Teresa. As you know, in December 2011 NSP-Minnesota filed a request to defer incremental 2012 property taxes, or alternatively, that a property tax rider be approved. In June the Minnesota Commission voted to deny our request for deferred accounting for incremental property taxes and also denied our request for a property tax rider.

Despite our disappointment in their decision, we believe the regulatory compact in Minnesota remains constructive. We felt our circumstances merited preferred accounting treatment. However, the commission ultimately ruled that this request did not meet the strict requirement for a deferral. As a result, we will continue to expense the full $24 million of incremental property taxes in 2012, resulting in a drag of approximately $0.03 per share on our 2012 earnings.

Now we considered accelerating the filing of our 2013 Minnesota electric rate case so that we could implement interim rates in late 2012 to help offset the impact of increased property taxes, lower sales, and added investments in Minnesota. However, based on our continued success managing O&M expenses, and with the help from warmer than normal weather in June and July, we decided to continue our plans, which anticipate a Minnesota electric rate case filing in early November.

So with that, I will turn the call over to Teresa.

Thanks, Ben, and good morning. Today I will discuss second-quarter results, provide an update on our regulatory calendar, discuss our financing plans, and update you on our 2012 earnings guidance. Let's begin by reviewing our second-quarter results for each of our four operating companies.

Earnings at PSCo increased $0.5 per share for the second quarter, due primarily to an electric rate increase effective in May 2012, lower O&M expenses, and warmer June weather. The increases were partially offset by decreased wholesale revenue due to the expiration of a long-term power agreement with Black Hills Corp.

Earnings at NSP-Minnesota were flat for the quarter. SPS earnings increased $0.01 per share for the second quarter. New rate increases in New Mexico and Texas, effective in January 2012, were partially offset by higher depreciation expense and property taxes.

Second-quarter earnings at NSP Wisconsin decreased $0.01 per share due to higher O&M expenses, partially offset by rate increases effective in January 2012 and warmer summer weather.

I will now discuss some of the key drivers that affected the income statement, beginning with retail electric margin. Our second-quarter electric margin increased $44 million. The primary drivers of the higher margins were $25 million from new rate increases in several states, but most significantly in Colorado; and $21 million from the estimated impact of weather. These positive items were partially offset by lower firm wholesale revenues due to the expiration of a long-term agreement with Black Hills Corp. and other less significant items.

Our quarterly weather normalized retail electric sales grew 0.5%, having a negligible positive impact on electric margin. Year-to-date weather normalized retail electric sales grew 0.4%? However, weather-normalized sales actually declined 0.2% when you remove the benefit of one additional day of sales due to leap year. We continue to forecast flat sales growth for 2012.

Turning to expenses, we continue to successfully manage O&M expenses in an effort to help offset some of the headwinds we faced in 2012. We began implementing O&M reduction initiatives in January to help offset the impact of lower than forecasted sales, warm winter weather, and the denial of our request for interim rates in Colorado.

As a result of these efforts, our O&M expenses were essentially flat on both a quarterly and year-to-date basis. We continue to forecast 2012 O&M expenses to increase up to 1%. This compares to our original expectation for a 3% to 4% increase. However, continued warm weather may put upward pressure on our O&M target.

Other taxes increased approximately $7.1 million or 7.7%, largely due to increased property taxes in Minnesota following the denial of our deferred accounting request. As a reminder, we are differing incremental property taxes in Colorado as a result of our recently approved multiyear plan.

I will now provide an update on several regulatory proceedings. In June NSP Wisconsin filed a request to increase electric rates by $39.1 million or 6.7% and to increase natural gas rates by $5.3 million or 4.9%. New rates are expected to be effective in January 2013. The electric rate filing was based on a 2013 forecast test year, 10.4% ROE, an equity ratio of 52.5%, and an average 2013 electric rate base of approximately $790 million.

The natural gas request was solely due to a proposal to recover the initial costs associated with the environmental MGP cleanup in Ashland. A Commission decision is anticipated during the fourth quarter of 2012.

In June 2011 NSP-Minnesota filed a request with the South Dakota Public Utilities Commission to increase South Dakota electric rates by $14.6 million, effective in 2012. The request was based on a 2010 historical test year adjusted for known and measurable changes, a return on equity of 11%, a rate base of $323 million, and an equity ratio of 52.48%.

In June 2012 the South Dakota commission authorized a rate increase of approximately $8 million, based on a ROE of 9.25%, an equity ratio of 53%, and full cost recovery for the Nobles wind project, which had been a contested issue in the proceedings. We are clearly disappointed in the authorized ROE granted in South Dakota. Nevertheless, we will continue to seek improved returns, and to that end, we filed a 2012 electric rate case in South Dakota in late June, requesting in $19.4 million increase in electric rates.

The request is based on a 2011 historic test year, adjusted for known and measurable changes for 2012 and 2013, a 10.65% ROE, a 53% equity ratio, and a rate base of about $370 million. We anticipate a Commission ruling in late 2012 or early 2013 with rates effective in early 2013.

One last rate related proceeding I want to mention is our request for approval of our investment in Smart Grid city in Colorado. As part of the 2010 electric rate case, PSCo requested recovery of the revenue requirements associated with our $45 million capital investment and $4 million of annual O&M costs incurred to develop and operate our Smart Grid project in Boulder.

In early 2011 the Colorado commission allowed partial recovery of the project, totaling approximately $28 million of the capital cost and all of the O&M costs. In December 2011 PSCo requested commission approval for the recovery of the remaining capital investment in Smart Grid. A decision is expected in the third quarter of 2012. The decision will not change the terms of the multiyear plan but would provide assurance of future recovery of these costs.

Looking ahead, we continue to consider plans to file several additional rate cases in the second half of 2012, including electric rate cases in North Dakota, Texas, New Mexico, and a Colorado gas case. In addition, in November we plan to file an electric rate case in Minnesota based on a 2013 test year.

This would allow for the implementation of interim rates in January. We will then consider options for pursuing a multiyear rate plan similar to what we achieved in Colorado. The Minnesota Commission is considering a process to establish parameters for such a plan, and we intend to actively participate.

I would now like to update you on our financing plans for the remainder of 2012. In July 2012 we entered into amended five-year credit agreements with a syndicate of banks, replacing the previous four-year credit agreement. The amended credit agreements have substantially the same terms and conditions; however, with an improvement in pricing and extension of maturity from March 2015 to July 2017.

Our 2012 financing program continues to develop as planned. During the second quarter we issued $100 million of first mortgage bonds at SPS. This quarter we plan to issue $800 million of first mortgage bonds at both NSP-Minnesota and PSCo. We also plan to issue approximately $100 million of first mortgage bonds at NSP-Wisconsin during the second half of the year. Financing plans are subject to change depending upon capital expenditures, internal cash generation, market conditions, and other factors.

In a challenging year marked by warm Winter weather, tepid electric sales, and some regulatory decisions that worked against us, we are proud of our efforts designed to deliver 2012 EPS within our guidance range. Taking early measures to reduce O&M expense and securing approval of the multiyear plan in Colorado demonstrate our ability to consistently deliver on our financial objectives.

Since 2005 we have established a strong track record, and we remain committed to delivering 2012 earnings within our guidance range. That concludes my prepared remarks. Operator, we will now take questions.

(Operator Instructions). Travis Miller, Morningstar Security Research.

Good morning. I wanted to go a little more into the usage patterns that you are seeing. On a weather-adjusted basis -- the flattened, and what you guys have booked so far in terms of usage growth, which jurisdictions are you seeing more positive weather-adjusted usage signs, which more negative? And then to the extent that you might be seeing DSM and conservation programs affecting that, do you think you are fully realizing the lost margin through those riders that you have?

Those are all great questions. Let me just try to answer your first question. I think the strongest sales that we are seeing are at SPS based upon the energy-related businesses they have down there.

We are also seeing, on the C&I side, some pretty good pickup in Wisconsin. Again, that is energy related, but in this case it is more sand mining, which has really become quite the business in that part of Wisconsin.

I think we are seeing some growth in the last quarter with PSCo and in Colorado. Again, I think that is primarily energy related. And then when you move to Minnesota, it has been pretty sluggish across the board in both the C&I and residential class. And Travis, just as a broad stroke, we are adding residential customers, but the residential usage is definitely less per household than it has been in the past, so that is something we are watching very closely.

And maybe that segues into your second part of your question -- what is the impact of DSM? It has been pretty attractive for us, but we do believe it shaves off 70 to 80 basis points on our sales growth expectation. I guess the thing that we continue to analyze this whether or not there is a shadow effect to that that perhaps we are not getting compensated for. But it's certainly, in Minnesota, is pushing us into rate cases pretty quickly.

I imagine that is one of the key issues, then, coming up in November you will address -- usage?

Yes. We have tended to mis-forecast what sales were going to be. We have been too optimistic. So we'll have to make sure that we temper that optimism coming into this rate case.

Great. That is very helpful. Thank you.

Kit Konolige, BCG Financial.

Good morning. On the Minnesota regulatory process -- so Teresa, you mentioned the Commission is, I think you said, working on a process that would, I gather, give some clarity on how a multiyear plan would work? Is that how to think of it? Can you give us some color on that?

You're thinking of it correctly, and in fact, they are going to have a preliminary discussion about that today. So that is exactly right. It is not just for us, but it is for all utilities.

And would you expect that then they would give you some pretty specific ideas that you could file for a three-year rate deal? I mean, how should we think of what to expect from what they are doing now?

Well, Kit, I think it is early to say exactly what would come out of that. Our plan right now is to file the one year and then pursue, like we did in Colorado, ultimately a multiyear -- essentially a fifth part of that as we move forward in that case.

Okay. Any idea on when they would have some specifics on multiyear rate making?

Well, comments are due in October, and we will just proceed through the process in the fourth quarter.

Right. And so obviously, that should be available -- some sort of feedback from the Commission should be available before you file that rate case?

It could be, but our plans are as I indicated, Kit.

Right, okay. And in Colorado, I think the idea was when you got the three-year deal, then that would help you to manage to the revenue outlook that you saw then. Can you give us some idea of how the Colorado business is going in terms of achieving allowed ROE and what the prospect for that is going forward?

Well, as you recall, we have the 10% parameter, and we'll share above that, but in terms of -- we are feeling good that this is going to provide sufficient revenue relief in terms of meeting our objectives.

Okay, great. Thank you.

Kit, I guess I would add that all of our jurisdictions with the exception of Minnesota probably are going to be in the mid-9% ROEs this year. Minnesota will not be in the 9%s, which is the reason why we have to file the rate case. I think he is off the line.

Ali Agha, SunTrust.

Teresa, Ben, when you talk about managing your O&M costs, and you originally thought that would be a 3% to 4% escalation, now you are looking at 1% or so. How much of that is a permanent reduction in knowing O&M? How much is timing and temporary? How should we think about O&M going forward from an escalation perspective?

In terms of O&M just in general, as we go through a year we have variations. We move projects around.

In terms of the longer term, we would expect to be more in the -- around 3%, potentially 4% range increases. So this year, as we said, 0% to 1%, and we would expect to get back on track to a 3% to 4% next year and in the future after that.

Okay. And then secondly, could you remind us, if we start off on your 2012 -- used 2012 as a base in terms of your rate base currently across the portfolio and look at the CapEx that you budgeted for the next 4 to 5 years, what is the underlying annualized rate base growth that CapEx is supporting starting from a 2012 base?

It is less than 7%, around 6% or so.

And that is the reason you are using 2012 as a base, right?

Yes.

Okay. And last question, Ben, you alluded to the fact you are going to be earning mid-9% across every jurisdiction other than Minnesota. Remind us what is embedded in -- for Minnesota this year? And that's -- these are ROEs at the utility, right? We are not talking any corporate leverage, etc., on top of that?

Yes, I was talking about utility ROEs. I think Minnesota will probably be in the 8% range. Obviously, losing $24 million in property tax hurts. Sales have been -- continued sluggish in Minnesota, so that is the reason why it is the laggard.

I would add to that, Ali, at a consolidated basis, we expect to be just slightly above 10%.

Okay, but that is, again, at the corporate?

Yes.

Okay. And you have been talking about the lower end of the range, but you have also been talking about better weather, etc. Is there a scenario that you could actually go to the higher end of the range as the year progresses, or is it just too -- given where we are, is that probably not realistic?

I think, Ali, we are giving you the best shot of where we see it now. Clearly, July -- we have not closed the books on July -- but weather has been favorable in July.

We have some more regulatory proceedings to go through, and we will keep watching the sales. So I think we will be in a good position to update you better in the third quarter, which is typically when we refine our estimates anyway, because that is our earnings season. So stay tuned.

Understood, thank you.

Paul Fremont, Jefferies.

Thank you very much. The first question I have is with South Dakota. What drove their decision for that level of ROE? Is there -- I mean, if South Dakota is coming in low, does that have an effect on the surrounding states and their way of thinking about ROE?

Well, I would just have to tell you, we totally disagree with the ROE that we were given, and it pushes us right away to filing a rate case again, as Teresa mentioned, and it is an historic test year. So you have got lag on top of that. And it is disturbing to us.

Clearly, we want to see it get better. If it doesn't get better, we'll have to figure out what we are going to do going forward, because your question is a good one. Capital needs to go where it is being rewarded. Right now, I think it was an unintentional signal, but I think the South Dakota Commission is saying, we don't want you to spend money on the infrastructure. That is certainly -- when you get that kind of return, that is what it is telling you.

And just to add, in terms of your question about influencing our other jurisdictions into that same level, obviously there is pressure on ROEs all over, but do we see that in Minnesota or North Dakota to that degree? Not to that degree outside of just normal pressures on ROE.

And then my second question is, how does the Minnesota decision on the tax recovery impact your strategy for future settlements? Because obviously, under the settlement the parties were amenable to allowing you to recover those costs, but you still got shot down by the Commission. So does that make it more difficult to settle?

The staff did not sign off on that. So ideally we would have had staff signoff. So we will have to work harder on that going forward.

Settlements still make a lot of sense. We did that in Colorado, and we will continue to try to do things like that in Minnesota. But we were clearly disappointed.

Thank you very much.

(Operator Instructions). Dan Eggers, Credit Suisse.

Good morning. Going back to the Minnesota comments, kind of in the nature of a slower growth environment, what elements do you think are going to be most important to get a multiyear structure done as you lay out a plan with the Commission?

Well, I think the benefits of a multiyear plan from a customer perspective is certainty. We kind of -- it's just a great opportunity to talk about the infrastructure refresh challenge, of the need for that, lay that out with stakeholders, get them to understand it, and have them understand what the rate impact is to them.

I don't think that goes away in a low sales environment or a high sales environment. I just like the transparency. Now on our end, clearly, when we know what our revenue is going to be in the next 3 years, I think it positions you better to manage your O&M, manage your capital budgets, and manage through your revenue expectations. So I think it works for both. Hopefully that answers your question. Did it?

Well, I guess along the lines of what sort of mechanisms do you think need to be in place, as far as revenue protection if the slower volumes offset the higher rate of O&M cost inflation, and open-ended property tax, and things like that?

Well, like so many other things, there is give-and-takes. If you cannot agree on what the sales are going to be, one of the things you can do is have some kind of true-up mechanism, maybe a band like we did down in Colorado, where if it gets -- it erodes past a certain point, where you don't achieve a certain point, you have some kind of mechanism if it is an extreme.

That is part of the settlement process. But typically, if both parties see it differently, there is an opportunity to compromise on some mechanism that does not create a windfall or hurt anybody.

Okay. And just one other question on transmission investment. What opportunities are you guys seeing within the region as the EPA rules come into effect, and do we expect to see more coal plant retirement announcements in [myso]? Is that opening up more windows of spending from what's in the plan right now?

I don't know if it is going to do that much for transmission -- the retirements. I mean, there's -- but to answer your question, the opportunities for transmission investments are enormous in all of our territories, and the upper Midwest is no exception. It happens to be where we are further along in the development of those plans, and we are going to spend -- what is it, Teresa? -- close to $4 billion over the next 5 years?

Right, that is correct. Out of our $13 billion budget. So it's a pretty robust budget right now. Right now.

Okay, thank you guys.

Michael Bates, D.A. Davidson.

Good morning. On your guidance, as you talk about the rider revenue expected to be $35 million to $45 million higher than last year, do you have the number as far as where you are at midyear?

Michael, can you restate the question? You were breaking up a little bit there.

Sure. I was wondering -- in your guidance, you assume that rider recovery is $35 million to $45 million higher than it was in 2011. I'm wondering, do you have the number to show us where you are at midyear?

I would say we are on track. The biggest variation in terms of the variance is due to the PSIA, the new rider in Colorado related to gas infrastructure investments.

So nothing different in terms of our assumptions from prior quarters around that. So we are not seeing any necessary updates from where we have been.

Okay, great. And then going back to your comments on the Brush Power assets, and I'm sorry if I missed this earlier, but when do you expect to put those into the PSCo's rate base?

We expect the transaction to close the early part of next year.

All right. And you would expect it to immediately go into the retail rate base, then -- right upon closing?

Typically, remember, it is under a PPA right now. So embedded in our rates right now is a capacity recovery.

Okay, thank you.

Thank you, and there are no further questions. I would like to turn the call back to Teresa for any closing comments.

I want to thank you all for participating in our second-quarter earnings call this morning. If you have any follow-up questions, Paul Johnson and the IR team are available to take your calls. Thanks.

Thank you, ladies and gentlemen. This concludes the Xcel Energy conference call. If you would like to listen to a replay of today's conference, it will be available for the next 24 hours by dialing 303-590-3030, or 1-800-406-7325 with the access code of 4548947. ACT would like to thank you for your participation. You may now disconnect.